New Internal Revenue Service (IRS) guidance on what it takes to start construction of a solar project raises practical questions, but it is very helpful in keeping the industry humming along.
Solar projects that are under construction by the end of 2019 qualify for the 30 percent investment tax credit. The credit dips to 26 percent for projects starting construction in 2020 and to 22 percent for projects starting construction in 2021. Projects meeting these deadlines must still be placed in service by the end of 2023 to qualify for a credit above 10 percent.
The credit drops to a permanent 10 percent level for projects that begin construction in 2022 or later. Projects that begin construction before 2022, but are not placed in service until 2024 or later, are also limited to the 10 percent credit.
The guidance had been delayed for some time, and developers were starting to worry that they would not have time to plan for projects projected for 2020 or later. This was particularly important for those bidding into Requests for Proposals or for very large projects. The International Trade Comission (ITC) amount helps determine the cost of the project, which ultimately leads to the price that the developer can bid for a PPA.
The guidance also applies to other technologies like fuel cells, CHP and geothermal projects, but we will leave them for another day.
As we suspected (and noted in our “Got ITCs” article distributed in connection with the Infocast Solar conference in March), the guidance largely follows a similar set of rules that apply to wind farms, which are based on more than 50 years of precedent. The IRS moved away from the wind guidance and precedent in several respects and made a few new clarifications.
The IRS has issued six sets of guidance on this issue in the production tax credit context since 2013.
The IRS has had a heck of a time implementing the wind rules. This is mostly because the very accomplished tax professionals at the IRS and the Treasury are tax specialists, not wind or solar specialists. They have not had years of project development and financing experience to be able to foresee some of the real world issues that arise when tax policy and weird financing trends meet. They were able to take some meetings with people on the ground, but there really were too many stakeholders to see everyone.
So, where does this leave us?
The new rules use a dual-pathway approach to determine whether construction started by a given date.
One pathway requires “physical work of a significant nature” to begin. That physical work must then continue until completion. The other pathway requires the taxpayer to “incur” at least 5 percent of the total cost of the facility. As with the first method, the taxpayer must make continuous efforts to advance toward completion of the facility. Of the two, the continuous efforts concept is theoretically easier to meet because it does not require continuous physical work.
Any facility that is placed in service by the end of the fourth calendar year after the year in which construction begins will be automatically considered to have satisfied the continuous construction or continuous efforts requirement. This is true even if there is a long gap between when physical work starts in 2019 (or earlier) and when the work resumes in a later year. The IRS refers to this test as a “continuity safe harbor.”
The need for a continuity safe harbor is questionable, since (1) there is a statutory deadline to the credits higher than 10 percent, and (2) what it takes to show that you moved the ball forward continuously is not readily definable (which is why we have the continuity safe harbor in wind).
The IRS said in 2016 that a taxpayer cannot buy more time under this continuity safe harbor by relying on the physical work test and the 5 percent test in alternating calendar years. For example, a taxpayer cannot rely on the physical work test in one year and then claim that it incurred at least 5 percent of the total cost of the facility in the next year. The IRS applied the same rule to solar, but it does not apply to projects that started work prior to January 1, 2019 (although an example (inconsistently) says that, if you start construction with one method in 2018 and then another in 2019, you have to use the 2018 method for determining the four year rule).
Practically, in order to be sure that financing will be available, developers should assume that they have to finish the project within four years after the year they start construction.
Five Percent Test
As stated above, the 5 percent pathway requires that a project owner incur at least 5 percent of the project’s cost prior to the construction start deadline. The “project’s cost” for this purpose means the cost of that portion of the facility that qualifies for five-year accelerated depreciation (basically, the equipment necessary to generate electricity from solar power).
A cost is incurred only when it is incurred under the taxpayer’s method of accounting. If it is a cash basis taxpayer, then the cost is incurred when the cash goes out the door. Accrual basis taxpayers “accrue” costs only when all events that give rise to the liability have occurred, the amount owed can be determined with reasonable accuracy, and “economic performance” has occurred. Economic performance occurs when the item or service is delivered, title passes (along with risk of loss), or the item or service is accepted, with one main exception.
The IRS rules do not define title, delivery or acceptance, so it is best to try to boil the concept down to either physical or constructive possession. Take physical possession. Take risk of loss (bear insurance costs). Take legal title and accept the item (through a bill of sale if possible).
We often see equipment “delivered” ex works, which means at the factory just after it is made. This is technically fine, but it puts more pressure on whether the buyer has constructive possession. The buyer should make sure that the seller segregates the purchased equipment from other equipment at the factory, and the buyer should pay for transport (if possible) from the factory to the site or storage facility.
If a taxpayer cannot prove that it incurred costs under these rules, it can look to a contractor’s costs. However, only costs incurred under a binding written contract with the taxpayer count. The binding written contract rules are discussed in detail below.
The one exception to the rules described above (for accrual basis taxpayers) is called the “three and a half month” rule. This treats a payment as incurred on the date paid if the taxpayer takes physical or constructive possession within three and a half months of the first payment for the equipment. If more than one item is ordered, then all of the items must be provided within the three and a half month period.
It is important to note that the payment may not be funded by the seller of the equipment. This kind of arrangement calls into question whether the payment was real and whether the buyer truly incurred the costs. Related buyers and sellers should generally stay away from the three and a half month test to avoid getting caught up in this rule. Rather, the buyer (from a related seller) should take physical or constructive control of the equipment by the year-end construction start deadline.
During the cash grant era (generally 2009 to 2012), it was not uncommon to finance panel supply contracts that were used to grandfather projects with debt, and solar developers may find this to be an attractive option as they think ahead to 2019 and 2020. One of the big issues is collateral. Should the lender get a lien on only the “magic” components, or the project as a whole? Are there even projects at this point that could be put up as collateral? Is there a corporate guarantee as an alternative?
Also keep in mind that any payment made outside of the three and a half month window will not count. We often hear people say that they think that the rule is that you had to pay by the deadline and take delivery by mid-April of the next year.
This is only true if you paid the entire purchase price at the end of December. For example, if you make monthly payments for equipment at the end of each month throughout 2019, you can include the December payment only if you do not receive the equipment until April 10, 2020. Any payments that were made between January and November 2019 do not count because they were outside of the three and a half month window.
While the test requires 5 percent or more to be spent by the relevant deadline, developers will be smart to spend significantly more if there is any chance of a cost overrun (and lenders will likely require the same). In the cash grant days, lenders and investors typically required upwards of 7 percent to be spent to have some cushion. We might see that push to 10 percent or more for some solar projects due to some quirks in the guidance.
If final costs are higher than expected, the developer is permitted to treat independent project units (strings or blocks) and size down the project to run the 5 percent test. However, because many costs are allocated ratably among project assets, merely cutting 10 percent of the project off of the calculation may not fix the glitch in all cases. The numerator and denominator of the fraction used to determine the percentage spent by the deadline would both be reduced.
In addition, because rooftop projects are treated as one unit under the guidance, there is no ability to cut them down into smaller components in order to get under the 5 percent mark. The only practical course is to incur well above the 5 percent mark prior to the deadline.
Physical Work Test
If a solar developer cannot show that it incurred at least 5 percent of the project’s costs by the applicable deadline, you can show that you started construction by starting significant physical work.
The legislative history and guidance under the tax credit grandfathering rules has consistently said that work merely has to “start.” The IRS and the Treasury have applied this concept in the production tax credit guidance as well. There is no reason to believe that the bar will be higher for solar. Congress intended for projects to be built. The rules merely require one to start the work.
Both on-site and off-site work can count.
The work can be performed by the taxpayer, by a contractor or by a subcontractor of the contractor. However, any work done by a contractor counts only if it is done under a binding contract that is in place before the work starts.
Legislative history suggests that this means that the contract must be binding by the applicable deadline and that the focus of the inquiry is on only the contract between the taxpayer and the first-level contractor (i.e., excluding any subcontracts). However, some tax counsel take a narrower view.
Some investors (and/or their counsel) require a binding contract for each subcontract as well if a sub of a sub of a sub (for example) is the person doing the actual work. The legislative history (going all the way back to 1966) is clear that this is not required. The history says that the contract needs to be binding only with respect to a distributor or middleman. Nevertheless, certain tax lawyers have required it recently because they are being asked to give exceptionally high level tax opinions.
Though the requirement is of questionable relevance, the thought is that it is safer to have binding contracts all the way down the chain than only at the taxpayer-contractor level. This kind of inquiry can run into practical roadblocks where contractors (or their subs) are reluctant to share confidential details of their manufacturing arrangements with tax equity.
Any components manufactured off site cannot come from the manufacturer’s inventory and cannot be equipment that the manufacturer normally holds in its inventory. Basically, real work has to occur that would not have occurred without the taxpayer placing the order. Here again, some conservative tax lawyers become concerned if the equipment does not appear “customized” to a particular project, as opposed to merely being custom ordered for the taxpayer.
They want the equipment to be “bespoke” in the traditional sense. That is, it is not only made for the client, but it is made for the client project’s specific measurements.
If the noninventory rule were to apply to solar, it would be hard to find much equipment for which a solar project could claim that it started construction based on off-site manufacturing. Racking and carports designed specifically to fit a site are not normally held in inventory. The same should go for transformers as a general matter, but only very large projects have their own transformers. Work on a transformer that will be owned by the utility does not count.
Manufacturing work on solar panels or cells would not count, unless there is a major shift in policy to accommodate solar projects. They are clearly of a type normally held in inventory.
The physical work must be on equipment that is an integral part of the generating facility as opposed to transmission equipment, land (other than certain roads) or buildings. The IRS said in an internal memo in 2011 that all of the equipment at a substation used through the point where the electricity is stepped up to transmission voltage, plus equipment beyond the step-up transformer if the equipment is related to the functioning of the transformer or transfer equipment, is an integral part of the power generating activity and is therefore qualified property.
The IRS guidance on production tax credit construction-start issues gives four examples of physical work that it thinks is “significant” enough to pass the test.
In the first example, a developer had a contractor excavate and install concrete pads for 20 percent of the turbines for his wind farm. For the solar guidance, the IRS noted that one could start physical work of a significant nature by installing 10 of 50 supporting structures to affix components of the project to a foundation. Query what this means where the project is merely ballasted or the racking is merely vibrated into the ground. Many solar projects do not have foundations in the traditional sense. They might be ballasted on the roof of a commercial building, or they might merely be attached to racking on a residential building or vibrating a tracker into the desert.
Consistent with the wind guidance, the IRS clarified that there is no spending minimum for the physical work test. The test is whether the work that started is on something that is qualitatively significant. That is not to say that investors will not impose a monetary threshold anyway, but the IRS has repeated time and again that one does not exist. Second, the PTC guidance says that “physical work on a custom-designed transformer that steps up the voltage of electricity produced at the facility to the voltage needed for transmission is physical work of a significant nature.” This is because you cannot use the power that you produce if you cannot get it to market. It needs to be at either transmission or distribution voltage to use it if you are not using the power on site. That said, the solar guidance is inconsistent on this front. We have a call into the IRS national office to clarify. One part of the guidance says that off-site physical work of a significant nature may include transformers that are used to step up voltage to less than 69kV. Where would that leave utility scale projects where they have to go from less than 69kV to (often) 220 kV? Another example says that work on a custom designed transformer that steps up electricity to the voltage needed for transmission (69 kV or greater) will be considered.
The result of the inconsistency likely means that, absent clarifying comments or guidance, we will not see transformer qualified projects get financed by sophisticated counterparties.
Starting construction on “string roads” (i.e., roads for equipment to operate and maintain the qualified facility) also constitutes physical work of a significant nature. In contrast, work for roads that are primarily used to access the site or that are primarily used for employee or visitor vehicles does not qualify. Most solar projects likely either do not have any roads or they have only access roads. Only the biggest projects will have meaningful amounts of roads.
It remains to be seen what level of on-site physical work investors will permit to count for solar projects. In any case, the options for solar appear much more limited, except in the case of larger utility scale projects. In the Treasury grant days, the investor community preferred the 5 percent safe harbor because the physical work test was largely unworkable. No one knew (or could get comfortable with a good deal of conservatism) what on-site work of a significant nature meant, except for the largest utility scale projects. In those cases, we often saw investors (and the Treasury) count a combination of road work that permitted maintenance (and was not merely an access road), water well drilling, and/or transformer or substation construction.
The problem with the comparison to wind for on-site physical work is that wind turbine foundations are typically 70-80 feet in diameter and six to eight feet deep. You should consider what work you can do on site or off that is qualitatively significant.
While work does not have to be quantitatively significant as a technical matter, investors will require it to be so, absent clear IRS guidance to the contrary. The more work, the better.
This does not mean that investors will not impose their own minimum spend threshold based on internal preferences.
For example, we are only recently seeing the larger tax-equity investors accept the position that off-site transformer fabrication is physical work of a significant nature, even though it has been specifically permitted under IRS guidance for several years. The unease is largely due to the fact that it may cost only $200,000 to begin the fabrication of a transformer that will be part of a $300 million project. Investors are coming around on the issue, but each has its own quirks as to what it thinks about the concept and what kinds of support it needs to see. The IRS national office staff has reiterated (again informally) this view, saying that it is not troubled by a low level of work as long as the work is of a significant nature. The government is protected by the requirement to show continuous work if the project is not placed in service by a certain date.
If work finishes after the later of December 31, 2018, or the end of the four-year “continuous work” presumption (applicable to wind and not yet clear whether it is applicable to solar), the IRS will closely scrutinize the work to ensure that it was continuous. The IRS has listed a number of tasks (generally outside of the developer’s control, like severe weather and financing issues) that are permissible disruptions in continuous work. It is unclear whether a disruption could include, for these purposes, the fact that a transmission upgrade is not expected to be made within the continuity safe harbor.
At the end of the day, the IRS developed the continuity safe harbor discussed above because the continuity requirements are unworkable in practice. No one really knows what they mean.
Single Project vs. Blocks
Under the wind tax credit guidance, multiple turbines that are operated as a single, integrated project are treated as a single facility for purposes of testing when construction started. The solar rules follow this concept, with an important exception. Rooftop systems (whether C&I or residential) are always treated as one unit, meaning that they cannot be split apart if there are cost overruns or if one part is delayed beyond four years or beyond the placed-in-service deadline.
The question of whether multiple units should be treated as a single facility depends on the facts. Facts that point to a single facility are that one company owns the entire project, all of the electricity is sold under a single power contract, all of the electricity moves to the grid through a single substation and intertie, the entire project is financed under a single loan agreement, all of the turbines are on contiguous sites, and all of the equipment is procured under a single turbine supply agreement.
Physical work counts only if it is done under a binding contract that is in place before the work starts.
A contract is binding only if it is enforceable under state law against the taxpayer or a predecessor and does not limit damages to a specified amount. For this purpose, a contractual provision that limits damages to at least 5 percent of the total contract price will not be treated as limiting damages to a specified amount.
In 2013, a group of wind generators, lenders and tax equity investors asked the Treasury to draw clear lines about how much work had to be done on turbine excavations, roads, transformers or other major components for a project to be considered under construction in 2013 (the deadline at that time). The IRS national office staff stated repeatedly on an informal basis that there was no definite minimum threshold for work. The analysis is based on a qualitative analysis of the work. That is, was the work on some material aspect of the project? The IRS then issued a new notice that confirmed the position, saying, “[a]ssuming the work performed is of a significant nature, there is no fixed minimum amount of work or monetary or percentage threshold required to satisfy the Physical Work Test.”
In the Treasury grant context, solar projects (other than residential projects) could be broken down into blocks that included one or more strings of panels and an inverter. The rationale was that, like a wind turbine, a string of panels and an inverter can operate independent of other strings of panels, in theory. The IRS declined to follow this path, which arguably is contrary to Revenue Ruling 94-31.
Larger projects are often completed in phases that begin in different years. In the wind context, the best practice is typically to assume that each phase needs to meet the start of construction rules independently. It is somewhat unusual for these kinds of projects to have enough commonality between phases for financiers to be comfortable that each phase is part of a single project. The same rationale should apply to large-scale solar projects.
Solar projects that are located on separate buildings should be analyzed independently from each other. We often see this in the context of solar projects on college or school campuses.
The IRS took a familiar path for project/equipment transfers, largely following the wind guidance.
The solar guidance permits transfers of “real projects” to third parties. That means that if you have a project that is at NTP or mechanical completion, it can be sold to a third party without losing its grandfather taint.
If you have only grandfathered equipment, like a transformer, solar panels or inverters that were acquired before the relevant deadline, they will lose their taint if they are sold outright to a third party.
You can contribute them to a partnership as long as you take an interest in the company equal to at least 20.1 percent of profits or capital. A partner’s share of capital is equal to its share of liquidation proceeds if the partnership liquidated. It is unclear what a partner’s share of profits is (the IRS has not defined it), so the best-case scenario is to give the partner a 20.1 percent or greater interest that does not vary over time.
It is important that the partnership be treated as a real partnership and not a contrivance. So, if the contributing partner wants to get out of the deal at some point, it should not be prebaked if possible. If the other partner wants a call option to buy that partner out, that could work, but in no case should it be for less than the fair value of the interest or before at least the date on which the project is placed in service (ideally, the option would be delayed until two years after the project is placed in service, but that is just our preference).
In no case should the contributor of the turbines get the right to put its interest to the other partners.
If a project is sold before NTP, it should have more than grandfathered equipment. Try to include a site lease, PPA, interconnection, other nongrandfathered equipment and an EPC contract if possible.
Key Observations for Solar
The 5 percent test (technically, but not economically) is the easiest path for solar projects.
It is the most objective test, and it will be the easiest path to “sell” to investors and their tax counsel, apart from the cost overrun issue noted above.
The 5 percent test also has the added benefit that, if you start construction with the safe harbor, you merely have to move development forward continuously by incurring costs or getting permits and other approvals, rather than continue with physical work on a continuous basis. The physical work test requires continuous physical work to proceed.
The 5 percent test has practical difficulties that must be balanced.
The 5 percent test is likely the more expensive path. The alternatives that involve merely “starting” work on qualitatively significant equipment can have a much lower barrier to entry. The developer of a $200 million project would need to incur $10 million under the 5 percent test. Alternatively, a developer can start construction on certain transformers (with a roughly $1 million price tag), paying less than 10 percent of the purchase price of the transformer prior to the construction start deadline.
The 5 percent test also brings with it the risk that equipment purchased for grandfathering purposes becomes outdated before a project can be deployed. We saw solar panels and inverters purchased for these purposes in connection with the Treasury grant program where project buyers were not interested in the grandfathered equipment. In some cases, it was due to the preference for “new” models of equipment. In others, it was because construction or permitting standards have evolved past the equipment purchased in prior years.
The most practical spend to include in a 5 percent safe harbor approach is to buy solar panels or inverters.
As a technical matter, any costs incurred with respect to the project’s solar generation equipment counts. However, if you look to costs other than the central generating equipment itself (accounting, legal, permitting, design, etc.), you run the risk that an investor will require part or all of the line items to be allocated to noneligible costs. Much of the allocation procedure is done by feel, meaning that there is more than one “right” way to make the allocation. The possibility of different approaches reduces the benefit of using the 5 percent test, which should be objective certainty.
For equipment purchased for the 5 percent test, make sure that you are very comfortable that you either (1) take physical or constructive delivery by the deadline or (2) pay for the equipment with your own money or a loan you take out from a third party (e.g., not the seller of the equipment).
If you pay for only the equipment by the deadline, make sure the equipment is delivered within three and a half months of the first payment. Make sure you check with your accountants on whether your tax methods of accounting permit you to use the three and a half month rule. A new taxpayer (partnership or corporation) can use the three and a half month rule, but this method’s use needs consistent going forward.
Make sure that there are no obligations to give the equipment back if the purchased equipment cannot be deployed.
Make sure that any “delivery” off site gives the buyer the right to visit the equipment and segregates the equipment from equipment that is intended for other buyers or projects. The buyer also should have legal title, pay for insurance, and pay for further shipping or installation. Do not rely merely on legal title transfer alone, even if people try to tell you that is what the words in the guidance say.
As for the physical work test, solar projects are harmed by rules that require work to occur on only items not held in inventory.
There just are not a large number of custom components for a solar project. If you have custom racking, carports or a transformer (for larger projects), you may be able to start work on those items. Everything else is generally held in inventory.
You should confirm that the contract was binding and written when the work started, and that each subcontract was binding and written as well.
Make sure that the contracts under which the work is performed are binding for state (or country) law purposes, that they state the specs of the item being purchased and that they do not permit either party to get out of the deal willy nilly.
If you have a termination option, the best course is to have the buyer pay damages of at least 5 percent of the purchase price plus (ideally) the value of equipment built to date. Make sure that any termination language that you add to a purchase agreement form does not conflict with the form’s existing termination or refund language.
If you adjust the terms of the contract after it is signed, run the changes by your tax lawyer. A change of the price by 10 percent or less should not be a problem, but some tax lawyers worry about certain changes, notwithstanding the fact that the price may not have changed significantly.
Do not include a right to suspend work at the buyer’s convenience. If you do include such a right, make sure that there is a date by which work must restart or termination will be presumed, triggering damages.
Unlike wind projects, which may have hundreds of large excavations and miles of new roads on a site, distributed generation projects (and even some large utility-scale projects) might not have any excavations and may be placed on a single roof.
This means that the only option for some solar projects to show that construction commenced may be to use the 5 percent safe harbor or to start construction of equipment off site. Because off-site construction can only be counted if it is on specially ordered equipment, this likely would eliminate any physical work prospects for most of the solar projects being built. That leaves these developers to rely on the 5 percent safe harbor, which, while viable, is vastly more expensive.